Carbon dioxide (CO2) is an undesired diluent that is present in many natural gas and other gas sources. The removal of CO2 is a common separation process in natural gas processing and is often required to improve the fuel quality (heating value) of the natural gas. Also, CO2 in the presence of water can be a corrosive agent to metal pipes. As a consequence, the removal of CO2 to acceptable specifications is required prior to transport natural gas or in pipelines. In the natural gas processing industry, various technologies have been employed for CO2 removal including chemical solvents, physical solvents, and membranes. By far, chemical solvents that reversibly react with CO2 are most commonly used for CO2 removal. Commonly used chemical solvents comprise amine solutions. Commercial amine solutions useable for this purpose include monoethanolamine (MEA), N-methyldiethanolamine (MDEA), and diethanolamine (DEA). In this process, the amine solution (amine and water) circulate in a loop between two key steps: absorption of CO2 and regeneration of the amine solvent. Although an effective CO2 separation process, amine treating presents several issues and challenges:                1. Intensive energy requirements: During the regeneration step, heating energy is required to break the chemical bonds between the absorbed CO2 and solvent. Energy is also required to generate steam within the amine regenerator to strip the CO2 from the solvent. For some particularly strongly-absorbing amines (e.g., MEA) and for large circulation rates, this energy requirement can be very high and represents a significant operating expense. Due to the high energy requirements, CO2-rich amine solutions are only partially regenerated to a lower CO2 loading (CO2-lean state) during the regeneration step.        2. Corrosivity of the amine: Amines can rapidly corrode low alloy steel such as carbon steel. Thus, only amine solutions (in water) with carefully controlled solution strengths are used to minimize corrosion of the absorption column, piping, and pumps. However, this diluted concentration requires higher circulation rates to achieve the desired CO2 removal. High circulation rates require larger process equipment (capital expense), increased reboiler duty (energy/operating expense) and increased pumping costs (energy/operating expense). Inhibitors are also typically used to control corrosion, but are often toxic.        3. CO2 loading capacity: CO2 loading capacity is limited by the concentration (or diluteness) of the amine solution. Also, the regenerated amine solution, although lean in CO2, still contains some absorbed CO2—reducing its capacity and reducing the driving force in the absorber. Thus, the effective, steady-state CO2 removal rate is further lowered. So, higher circulation rates than theoretical are required for removal of CO2 to desired levels. It is not recommended to attempt to boost loading capacity by increasing the amine concentration. This is due to increased corrosion potential effecting the longevity of the equipment. Even if corrosion inhibitors are used, serious viscosity problems can occur when using high concentrations of amines which can lead to hydraulic failures.        4. Degradation of amine: Amines react with CO2 (and H2S, COS, etc.) to form various different products that are not reversible in the regeneration step. Amines may also degrade thermally. The third, well-studied route of amine degradation is oxidatively, but that is mainly for flue-gas applications and not natural gas. Trace impurities like SOX, NOX also degrade amines. As a result, there is a ‘reclaimer’ used to remove the degradation products from the amine circulation loop. This ‘reclaimer’ step generates waste products and requires additional energy. Also, regular amine make-up is required to replace the lost amine. Disposal of the degradation products may also be a concern.        
Because of the significant costs involved, proper amine selection requires careful evaluation of these factors for the specific application since the criticality of these factors varies for different amines. In other words, one faces a trade-off and optimization between benefits and costs. Nevertheless, in general, the main disadvantage for amine-based CO2 removal processes remains the high energy consumption requirements.
Instead of chemical absorption with amine solutions as was discussed above, physical absorption with physical solvents (e.g., Selexol™, IFPexol™, n-formyl morpholine (NFM)) is another option for CO2 removal. The primary advantage of physical solvents over amine solutions is that lower energy requirements are needed since CO2 absorption is accomplished through physical solubility interactions—not chemical reactions. In fact, unlike the energy-intensive regeneration stripping columns in amine-based chemical absorption processes, CO2 recovery via physical absorption processes use a sequence of flash stages (i.e., successive pressure reductions) to desorb CO2 from the physical solvent. However, physical absorption processes also have several disadvantages:                1. Low CO2 capacity: Physical solvents tend to have lower CO2 capacities than amine solvents. Thus, higher circulation rates and larger equipment is needed. On the other hand, CO2 absorption tends to increase significantly with increasing CO2 concentration or partial pressure. So, physical solvents are most attractive for high-CO2 content gas.        2. Pickup of hydrocarbons: Significant amounts of valuable hydrocarbons are absorbed by physical solvents. For natural gas processing applications, some of these hydrocarbons can be lost in the CO2 waste stream.        3. High circulation rates: Physical solvent processes may require twice the circulation rate as amine solutions. Higher circulation rates result in higher capital and operating expenses. Also, absorber columns using physical solvents typically have more stages of contact and are therefore much taller than those employing amine solutions.        4. Solvent losses: Physical solvents can be entrained and lost to the treated gas. Refrigeration or water-washing may be used to minimize losses but this requires added capital expense and increased operating cost.        
Art that relates to the use of Ionic Liquids for separations include U.S. Pat. No. 6,623,659 ('659 patent) entitled Separation of Olefins from Paraffins Using Ionic Liquid Solutions to Munson et al. which provides a method for separating olefins from non-olefins. The '659 patent uses a Group 1B metal salt (preferably a silver salt) dissolved in ionic liquids for separating olefins from non-olefins including paraffins, cycloparaffins, oxygenates, aromatics, and oxygenates. The '659 patent does not relate to the separation of CO2 nor does use the class of ionic liquids used in the method and process of the present invention.
Another publication that discloses a method of separation using ionic liquids is US Patent Application Publication 2003/0125599 to Boudreau et al. Boudreau et al. relates to the separation of dienes form olefins using a Group 1B salt in an ionic liquid solution. The di-olefins or dienes can be selectively complexed by the Group 1B metal salt the separated from the uncomplexed olefins. Boudreau et al. does not discuss separation of CO2 or the use of an ionic liquid comprising a carboxylate moiety.
In light of the limitations of the physical and chemical processes discussed above it would be desirable to have a CO2 removal process with some of the features of the physical absorption processes (namely low energy for regeneration, low solvent losses, minimal corrosion problems) and also have some of the properties of chemical absorption processes (such as high loading capacity and low hydrocarbon co-absorption). The present invention provides a new process with just such desired features.